Method and materials for hydraulic fracturing with delayed crosslinking of gelling agents

ABSTRACT

A non-aqueous slurry contains a non-aqueous liquid immiscible in water (such as a hydrocarbon based oil) having dispersed therein a crosslinking agent (such as a borate crosslinking agent) and an oil-wetting surface active material. The non-aqueous slurry further contains an organophilic clay. The non-aqueous slurry, when used in an aqueous fracturing fluid, provides crosslinking delay between the crosslinking agent and a hydratable polymer, such as guar or guar derivatives. The aqueous fracturing fluid provides an enhanced fracture network after being pumped into a well.

This application claims the benefit of U.S. patent application Ser. No.62/043,795, filed on Aug. 29, 2014, and U.S. patent application Ser. No.62/211,435, filed on Aug. 28, 2015, both of which are hereinincorporated by reference.

FIELD OF THE DISCLOSURE

The disclosure relates to non-aqueous slurries, fracturing fluidscontaining such slurries and methods of using the fracturing fluids inthe treatment of a subterranean formation penetrated by a well. Thenon-aqueous slurries improve the performance of crosslinked fracturingfluids.

BACKGROUND OF THE DISCLOSURE

Hydraulic fracturing of conventional oil- and gas-bearing formationsrequires the high-pressure injection of a fracturing fluid from the wellinto the formation. During this process, the rock will fail, forming acrack or fracture. This occurs when the surface pumping pressure plusthe hydrostatic pressure of the fluid in the wellbore less the frictionloss from flow of the fluid through pipe and perforations exceeds theformation stresses.

The direction of the fracture created using conventional fracturingtechniques is away from the wellbore in a bi-wing manner andperpendicular to the formation's least principle stress. The fracturegrowth in bi-wing fractures continues as the pressure and the fluid rateentering the fracture are greater than the fluid lost to the formationfrom the fracture. Once fracture growth is initiated, small amounts ofproppants, such as well-rounded sand, having sizes ranging from 70/140to 16/20 mesh may be added to the fluid. Normally, the amount ofproppant per gallon of fluid increases as the treatment progresses.

The fracturing fluid is normally a high-viscosity fluid that can bedescribed as a gel or semi-solid. It is based on a gelling agent such asguar gum that is crosslinked with chemicals like borate ion, zirconiumand titanium chelates such as zirconium lactate and zirconium lactatetriethanolamine. The viscosity can range from 200 to 2000 cP at 40sec⁻¹, but typically ranges from 400 to 1000 cP at 40 sec⁻¹. Theviscosity is needed to create fracture width and to carry the proppantdeep within the fracture.

Conventional fracturing techniques are, however, often not acceptable inthe fracturing of shale and tight gas formations exhibiting apermeability less than 10 mD and in some cases lower than 1.0 mD andoften lower than 0.1 mD. (Permeability is a measure of the resistance offlow in porous materials like sedimentary formation rock.) Whereasconventional reservoirs require the creation of bi-wing fractures, thefracturing of low permeability formations, such as shale, requiresmaximizing complex fracture development, or the creation of secondaryand tertiary fractures forming off from the primary fracture. Twofactors promote fracture complexity. First, that the fracturing fluid bepumped at a high rate. Second, that the fracturing fluid be a very thinfluid.

While slickwater fracturing has become a preferred fracturing fluid inthe treatment of low permeability reservoirs, it has major drawbacks.Slickwater fluids are normally composed of water and 0.25 to 2.0gal/1000 gal water of a friction reducer. The friction reducers arenormally added to water as invert polymer emulsions based on anionic orcationic polyacrylamide. The low viscosity fluid does not allow adequateproppant transport in the fracture, nor does it create enough fracturewidth to fill the fracture with higher loadings of larger-sizedproppant. Slickwater fracturing is thus more suitable for high mobilitygas, where lesser amounts of proppant are required. For oil, which isless mobile than gas, the proppant has to be of a larger size and widerfractures are needed to adequately drain the reservoir. This iscurrently accomplished by the sequential pumping of slickwater followedby conventional high viscosity fluids, neither fluid having the idealcharacteristics to hydraulically fracture a shale reservoir.

Alternatives have been sought for low viscosity fluids which enhance thecreation of a fracture network in low permeability reservoirs and whichprovide enhanced proppant transport into the created fractures.

SUMMARY OF THE DISCLOSURE

The disclosure relates to a non-aqueous slurry having a non-aqueousliquid immiscible in water, an oil-wetting surface active material and acrosslinking agent.

In an embodiment, the disclosure relates to a non-aqueous oil slurry ofan oil having dispersed therein an oil-wetting surface active materialand a crosslinking agent. The non-aqueous oil slurry may contain anorganophilic clay.

In another embodiment, the disclosure relates to a non-aqueous oilborate containing slurry comprising an oil having dispersed therein acrosslinking agent and an oil-wetting surface active material. Thenon-aqueous oil borate containing slurry further contains anorganophilic clay. The oil-wetting surface active material has ahydrophilic and a hydrophobic portion. The crosslinking agent comprisesa borate salt. The borate salt may be selected from the group consistingof sodium borate decahydrate, sodium tetraborate decahydrate, sodiumtetraborate pentahydrate, sodium tetraborate anhydrous, sodiummetaborate and disodium octaborate tetrahydrate as well as mixturesthereof. The hydrocarbon based oil may be hydrotreated naphtha orraffinate.

In another embodiment, the disclosure relates to a well treatment fluidcomprising a non-aqueous slurry referenced in the paragraphs above aswell as a water-soluble gellant. Preferred water-soluble gellantsinclude underivatized guar, guar derivative, locust bean gum, tara gum,fenugreek gum, cellulose and cellulosic derivatives.

In another embodiment, the disclosure relates to an aqueous welltreatment fluid containing a non-aqueous slurry referenced in theparagraphs above and the water-soluble gellant. The viscosity of theaqueous well treatment fluid is less than 20 cP at 40 sec⁻¹; in mostcases, the viscosity is from about 10 to about 20 cP at 40 sec⁻¹. Theamount of gellant in the well treatment fluid is between from about 6 toabout 40 pounds per thousand gallons (pptg) of water. In a preferredembodiment, the amount of gellant in the well treatment fluid is betweenfrom about 8 to about 15 pptg of water. Further, the amount of gellantin the well treatment fluid may be between from about 10 to about 12pptg of water.

In another embodiment, the disclosure relates to a well treatment fluidcontaining a non-aqueous slurry referenced in the paragraphs above and anon-aqueous slurry containing the water-soluble gellant.

In another embodiment of the disclosure, a method of fracturing asubterranean formation is provided by pumping into the well an aqueouswell treatment fluid referenced in the paragraphs above. A fracturenetwork may be created in the formation after pumping of the aqueouswell treatment fluid.

In another embodiment, a method of enhancing the transport capability ofa proppant in a hydraulic fracturing operation is provided. In thisembodiment, a fracturing fluid comprising a gellant is pumped into awell. The loading of the gellant in the fracturing fluid is between fromabout 6 to about 40 pptg of water. The fracturing fluid further containsa non-aqueous slurry containing a non-aqueous liquid immiscible inwater, an oil-wetting surface active material and a crosslinking agent.The viscoelasticity of the fracturing fluid, as measured by its storagemodulus and viscous modulus, is enhanced by the presence of theoil-wetting surface active material in the fracturing fluid.

In another embodiment, a method of enhancing the transport capability ofa proppant in a hydraulic fracturing operation is provided. In thisembodiment, a fracturing fluid comprising a gellant of underivatizedguar, guar derivative, locust bean gum, tara gum, fenugreek gum,cellulose, cellulosic derivatives or a mixture thereof is pumped into awell. The loading of the gellant in the fracturing fluid is between fromabout 6 to about 40, preferably from about 6 to about 12, pptg of water.The fracturing fluid further contains an oil-based slurry comprising anoil having dispersed therein an organophilic clay, an oil-wettingsurface active material having a hydrophilic and a hydrophobic portionand a crosslinking agent comprising a borate salt or a borate ionreleasing compound including boric acid, alkali metal borates such assodium diborate, potassium tetraborate, sodium tetraborate,pentaborates, alkaline borates, zinc metal borates, boric oxide, sodiumborate decahydrate, sodium tetraborate decahydrate, sodium tetra boratepentahydrate, sodium tetraborate anhydrous, sodium metaborate anddisodium octaborate tetrahydrate and mixtures thereof. Theviscoelasticity of the fracturing fluid, as measured by its storagemodulus and viscous modulus, is enhanced by the presence of theoil-wetting surface active material in the fracturing fluid.

In another embodiment of the disclosure, a method for delaying thecrosslinking time of a gellant in water is provided. In this embodiment,gellant is added to water. A non-aqueous slurry containing a non-aqueousliquid, an oil-wetting surface active material and a crosslinking agentis added to the aqueous fluid containing the gellant. The oil-wettingsurface active material decreases the rate of wetting of thecrosslinking agent by water. The decrease in the rate of wetting mayalso be attributable to the combination of the oil-wetting surfaceactive material and non-aqueous liquid. This, in turn, delays thecrosslinking of the gellant with the crosslinking agent.

In another embodiment of the disclosure, a method for delaying thecrosslinking time of a gellant selected from underivatized guar,derivatized guar, locust bean gum, tara gum, fenugreek gum, cellulose,cellulosic derivatives or a mixture thereof in water is provided. Inthis embodiment, gellant is added to water. A non-aqueous oil boratecontaining slurry comprising an oil having dispersed therein a boratesalt crosslinking agent is added to the aqueous fluid containing thegellant. The non-aqueous oil borate containing slurry further containsan oil-wetting surface-active material and organophilic clay. The rateof wetting of the borate salt in the aqueous fracturing fluid isdecreased by the oil-wetting surface active material being dispersed inthe non-aqueous oil slurry. This, in turn, delays the crosslinking ofthe gellant with the borate salt.

In another embodiment of the disclosure, a method of enhancing therecovery of oil or gas from an oil or gas well is provided. In thismethod, an aqueous fracturing fluid having a viscosity of from about 4to about 20 cP at 40 sec⁻¹ is pumped into the oil or gas well during afracturing operation. The aqueous fracturing fluid contains (i) anon-aqueous liquid slurry containing a non-aqueous liquid immiscible inwater, an oil-wetting surface active material and a crosslinking agent;(ii) a gellant and (iii) an oxidative or enzyme breaker. The amount ofgellant in the aqueous fluid is between from about 6 to about 40 pptg ofwater.

In another embodiment of the disclosure, a method of enhancing therecovery of oil or gas from an oil or gas well is provided. In thismethod, an aqueous fracturing fluid having a viscosity of from about 4to about 20 cP at 40 sec⁻¹ is pumped into the oil or gas well during afracturing operation. The aqueous fracturing fluid contains (i) anon-aqueous oil slurry comprising a hydrocarbon based oil havingdispersed therein an organophilic clay, an oil-wetting surface activematerial having a hydrophilic and a hydrophobic portion and acrosslinking agent comprising a borate salt selected from the groupconsisting of sodium borate decahydrate, sodium tetraborate decahydrate,sodium tetraborate anhydrous, sodium metaborate, sodium tetra boratepentahydrate and disodium octaborate tetrahydrate and mixtures thereof;(ii) a gellant selected from underivatized guar, derivatized guar,locust bean gum, tara gum, fenugreek gum, cellulose, cellulosicderivatives or a mixture thereof and (iii) an oxidative or enzymebreaker. The amount of gellant in the aqueous fluid is between fromabout 6 to about 40 pptg of water.

In another embodiment of the disclosure, a method of reducing formationdamage to a subterranean formation subjected to a hydraulic fracturingoperation is provided. In this method, an aqueous fracturing fluid,having a viscosity of from about 4 to about 20 cP at 40 sec⁻¹, is pumpedinto a well penetrating the subterranean formation during the hydraulicfracturing operation. The aqueous fracturing fluid contains (i) anon-aqueous slurry containing a non-aqueous liquid immiscible in water,an oil-wetting surface active material and a crosslinking agent; (ii) agellant; and (iii) an oxidative or enzyme breaker. The amount of gellantin the aqueous fluid is between from about 6 to about 40 pptg of water.

In another embodiment of the disclosure, a method of reducing formationdamage to a subterranean formation subjected to a hydraulic fracturingoperation is provided. In this method, an aqueous fracturing fluid,having a viscosity of from about 4 to about 20 cP at 40 sec⁻¹, is pumpedinto a well penetrating the subterranean formation during the hydraulicfracturing operation. The aqueous fluid contains (i) a non-aqueous oilslurry comprising an oil having dispersed therein an organophilic clay,an oil-wetting surface active material having a hydrophilic and ahydrophobic portion and a crosslinking agent comprising a borate saltselected from the group consisting of sodium borate decahydrate, sodiumtetraborate decahydrate, sodium tetraborate anhydrous, sodiummetaborate, sodium tetra borate pentahydrate and disodium octaboratetetrahydrate and mixtures thereof; (ii) a gellant selected fromunderivatized guar, derivatized guar, locust bean gum, tara gum,fenugreek gum, cellulose, cellulosic derivatives or a mixture thereofand (iii) an oxidative or enzyme breaker. The amount of gellant in theaqueous fluid is between from about 6 to about 40 pptg of water.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Characteristics and advantages of the present disclosure and additionalfeatures and benefits will be readily apparent to those skilled in theart upon consideration of the following detailed description ofexemplary embodiments of the present disclosure. It should be understoodthat the description herein, being of example embodiments, are notintended to limit the claims of this patent or any patent or patentapplication claiming priority hereto. On the contrary, the intention isto cover all modifications, equivalents and alternatives falling withinthe spirit and scope of the claims. Many changes may be made to theparticular embodiments and details disclosed herein without departingfrom such spirit and scope.

As used herein and throughout various portions (and headings) of thispatent application, the terms “disclosure”, “present disclosure” andvariations thereof are not intended to mean every possible embodimentencompassed by this disclosure or any particular claim(s). Thus, thesubject matter of each such reference should not be considered asnecessary for, or part of, every embodiment hereof or of any particularclaim(s) merely because of such reference.

Certain terms are used herein and in the appended claims to refer toparticular components. As one skilled in the art will appreciate,different persons may refer to a component by different names. Thisdocument does not intend to distinguish between components that differin name but not function.

Also, the terms “including” and “comprising” are used herein and in theappended claims in an open-ended fashion, and thus should be interpretedto mean “including, but not limited to . . . .” Further, referenceherein and in the appended claims to components and aspects in asingular tense does not necessarily limit the present disclosure orappended claims to only one such component or aspect, but should beinterpreted generally to mean one or more, as may be suitable anddesirable in each particular instance.

The description and examples are presented solely for the purpose ofillustrating the preferred embodiments of the disclosure and should notbe construed as a limitation to the scope and applicability of thedisclosure. While the compositions of the present disclosure aredescribed herein as comprising certain materials, it should beunderstood that the composition could optionally comprise two or morechemically different materials. In addition, the composition can alsocomprise some components other than the ones already cited.

In the summary of the disclosure and this detailed description, eachnumerical value may be read as being modified by the term “about” aswell as being read by not being modified by the term “about”. Also, inthe summary of the disclosure and this detailed description, it shouldbe understood that a concentration range listed or described as beinguseful, suitable, or the like, is intended that any and everyconcentration within the range, including the end points, is to beconsidered as having been stated. For example, “a range of from 1 to 10”is to be read as indicating each and every possible number along thecontinuum between about 1 and about 10. Thus, even if specific datapoints within the range, or even no data points within the range, areexplicitly identified or refer to only a few specific, it is to beunderstood that inventors appreciate and understand that any and alldata points within the range are to be considered to have beenspecified, and that inventors possession of the entire range and allpoints within the range.

Further, reference to viscosity measured at 511 sec⁻¹ set forth hereinis measured with a Fann Model 35 type viscometer with an F1 spring, B1bob, and R1 rotor at a shear rate in sec⁻¹ at 77° F. (25° C.) and apressure of 1 atmosphere. Viscosity measurements made at 40 sec⁻¹ weremade using a high temperature high pressure Grace 5600 using a R1 B5 cupand bob at ambient temperature and at elevated temperatures encounteredin a shale reservoir (240° F.). The oscillatory shear measurements weremade with a Grace 5600 using a RIBS cup and bob at 72° F.

A complex fracture network may be created in a hydrocarbon producingreservoir by pumping into the reservoir a non-aqueous slurry containinga non-aqueous liquid immiscible in water. The slurry may be used in thefracturing of formations penetrated by horizontal as well as verticalwellbores.

The non-aqueous slurry has particular applicability in the treatment ofunconventional hydrocarbon reservoir formations such as low permeabilityor “tight” formations, such as shale, tight sandstone (typically havinga pore throat size from about 0.03 to about 2.0 μm) and coal bed methanewells. Typically, the permeability of such a formation is less than 10mD, more typically less than 1 mD. In a preferred embodiment, thenon-aqueous slurry may be used in the treatment of shale formations.

The non-aqueous slurry comprises a non-aqueous liquid immiscible inwater. The non-aqueous slurry further has a crosslinking agent and anoil wetting-surface active material. The slurry may further optionallycontain an organophilic clay with or without a clay activator.

The presence of the oil wetting-surface active material in thenon-aqueous slurry enables delayed crosslinking reaction time of thecrosslinking agent with gelling agent in the aqueous well treatmentfluid. While not intending to be bound by any theory, the delay incrosslinking time is believed to be attributable to the wettingcharacteristics of the surface active material to the crosslinking agentdispersed in the non-aqueous slurry. By enabling a delay in thecrosslinking reaction time, hydraulic horsepower is reduced duringpumping of the fluid into the well.

The increase in crosslinking time minimizes unnecessary frictionpressure in a pipe during pumping of the fluid into the wellbore. Highfriction pressures are problematic since they require higher hydraulichorsepower to fracture the well and, thus, increase operating expenses.

The non-aqueous liquid is typically a hydrocarbon derived oil and ispreferably a non-polar oil. Suitable non-polar oils include non-polarhydrocarbon oil including C₃-C₂₀ hydrocarbons including olefins. In apreferred embodiment, the non-polar oil is a refined oil such ashydro-treated naphtha or a raffinate oil. Other oils may include mineraloil or diesel oil. Vegetable oils may also be used.

The non-aqueous liquid of the slurry may also be a non-aqueous liquidimmiscible in water. Such liquids may include alcohols, ketones,carboxylic acids, fatty acids, fatty alcohols, amines, amides as well ascarbon disulfide.

Typically, the amount of non-aqueous liquid in the slurry is betweenfrom about 100 to about 500, preferably from about 200 to 235, poundsper barrel (ppb) of the non-aqueous slurry.

The crosslinking agent is typically a borate compound or other boronreleasing compound. The borate crosslinking agent can be any borate ionsource and includes organoborates, monoborates, polyborates, mineralborates, boric acid, borax, sodium borate, including anhydrous or anyhydrate, borate ores such as colemanite or ulexite as well as any otherborate complexed to organic compounds to delay the release of the borateion, such as taught in U.S. Pat. No. 5,145,590.

Typically, the crosslinking agent is a borate salt such as sodium boratedecahydrate, sodium tetraborate decahydrate, sodium borate pentahydrate,sodium tetraborate anhydrous, sodium metaborate and sodium octaboratetetrahydrate as well as combinations thereof. In a preferred embodiment,the borate salt is disodium octoborate tetrahydrate. Typically, betweenfrom about 30 to about 250, preferably from about 65 to about 135, morepreferably from about 83 to about 116, ppb of the non-aqueous oil boratecontaining slurry is the borate salt.

When the crosslinking agent is a borate salt, the oil slurry furthercontains dispersed therein an organophilic clay. The organophilic clayacts as a suspending agent to keep the borate salt dispersed in the oiland to provide a uniform (or even) distribution of the crosslinkingagent in the dispersion.

The organophilic clay, which associates with oily surfaces and rejectsaqueous surfaces, may be the reaction product of purified smectite clay(such as hectorite, bentonite, attapulgite, sepiolite, montmorillonate,etc.) and a quaternary ammonium salt. It includes coated clay (orlignite) such as clay coated with a fatty-acid quaternary amine. Thecoating imparts dispersability of the clay in the oil. Exemplaryorganophilic clays include those disclosed in U.S. Patent PublicationNo. 20070197711 and U.S. Patent Publication No. 20100305008, hereinincorporated by reference. Included here are organo bentonites such asBENTONE® clays of Elementis Specialties, Inc. and Claytone SF, a productof Southern Clay Products. Further, such organophilic clays may be ionexchanged clays. See, for instance, U.S. Patent Publication No.20010056149, herein incorporated by reference. Typically, between from 2to about 40, preferably from about 6 to 10, more preferably from about 8to about 8.5, ppb of the non-aqueous oil borate containing slurry is theorganophilic clay.

The clay may need to be activated in the non-polar oil. Suitable clayactivators include propylene carbonate, ethanol and combinationsthereof. When present, the amount of clay activator typically rangesfrom about 15% to about 75%, typically from about 25 to about 60%, moretypically from about 40% to about 50%, by weight of the clay.

The oil-wetting surfactant aids in the wetting and/or dispersion of thecrosslinking agent by the non-aqueous liquid. Preferred oil-wettingsurfactants are those having a tendency to absorb onto the surface ofthe crosslinking agent and include cationic surfactants as well asnon-ionic surfactants.

Thus, the oil-wetting surface active material has a hydrophobic part anda hydrophilic part that has a strong affinity for the crosslinkingagent. While not being bound to any particular theory, it is believedthat the oil-wetting surface active material absorbs onto the surface ofthe crosslinking agent such that the crosslinking agent becomes oil wetover a longer period of time. When the non-aqueous slurry is added towater, the crosslinking agent does not immediately dissolve.Crosslinking of the crosslinking agent and the gellant is thereforedelayed. Typically, there may be a 90 second to 3 minute delay time. Thedelay may be regulated based on the oil-wetting surface active materialand the amount of oil-wetting surface active material in the non-aqueousslurry. Thus, instantaneous crosslinking of the crosslinking agent andthe gellant is delayed by regulating the dissolution time of thecrosslinking agent; the dissolution time being regulated by theoil-wetting surface active material absorbed onto the oil coated or oillike state of the crosslinking agent.

Suitable oil-wetting surface active materials for delaying thecrosslinking of the gellant with crosslinking agents include thosehaving one or more hydroxyl groups or derivatives thereof on the polar(hydrophilic) part of the oil-wetting surface active material.Preferably the oil-wetting surface active material has more than onehydroxyl, ether and/or ester group. In addition to delaying thecrosslinking, the surface active member further thins the viscosity ofthe slurry.

The amount of oil-wetting surface active material in the non-aqueousslurry depends on the desired delay time and the viscosity limits neededfor the stability of the slurry. The required delay time can bedetermined from well data and the time needed can be adjusted by theconcentration of the oil-wetting surface active material in the slurry.Typically, the amount of oil-wetting surface active member dispersed inthe slurry is between from about 0.05 to about 10, preferably from about0.05 to about 30 percent by weight based on the weight of the slurry. Insome embodiments, relatively low amounts are preferred for example 0.05to 10, preferably from about 0.05 to above 3, more preferably from about0.1 to about 1.0, percent by weight based on the weight of the slurry.In other embodiments, higher amounts are preferred, for example 10 to 30percent by weight, based on the total weight of the slurry.

Preferred oil-wetting surface active materials include polyhydricesters, such as sorbitan esters (esterified dehydration products ofsorbitol). The fatty acid portion of the ester is normally derived fromfatty acids having from about 6 to about 30, preferably from about 12 toabout 20, carbon atoms. Typical examples of said fatty acids beinglauric acid, myristic acid, palmitic acid, stearic acid, oleic acid, andbehenic acid. Preferred sorbitan esters include sorbitan monooleate,sorbitan monolaurate, sorbitan monopalmitate and sorbitan trioleate.Further preferred are polyoxyethylene glycol sorbitan esters (like thosehaving an HLB value of 14 or more). Suitable polyoxyethylene glycolsorbitan esters include polyoxyethylene glycol sorbitan hexaoleate andpolyoxyethylene sorbitol hexaoleate.

Ethoxylates of the sorbitan esters may also be used wherein one or moreof hydroxyl groups may contain from 1 to about 20 oxyethylene units aswell as mixtures thereof. Examples include POE(5) sorbitan monooleate,POE(2) sorbitan monooleate, POE(20) sorbitan monolaurate, etc.

Other preferred oil-wetting surface active materials include alkoxylated(such as ethoxylated, propoxylated, ethopropoxylated) glycerides ofplant or animal origin. Suitable mono-, di- and tri-glycerides may bederived from lard, tallow, ground nut oil, butter oil, cotton seed oil,linseed oil, olive oil, palm oil, palm kernel oil, canola oil, grapeseed oil, fish oil, soybean oil, castor oil, rapeseed oil, copra oil, orcoconut oil and comprise a total number of alkoxylated units between 1and 60, are suitable. Preferred are ethoxylated glycerides. The numberof alkoxylated units in the polyalkoxylated glyceride is typicallybetween from 1 to about 60.

Alkoxylated glycerides may be obtained by alkoxylation of the mono-, di-or tri-glyceride by an alkylene oxide such as ethylene oxide, propyleneoxide or butylene oxide or mixtures thereof; or by transesterificationof a glyceride with a polyalkylene glycol. In a preferred embodiment, anethoxylated mono or diglyceride is prepared from glycerol; linear orbranched C₄-C₃₀, preferably C₁₀-C₁₉, more preferably C₁₂-C₁₈ fattyacids; and 2 to 30 ethoxy and/or propoxy units, preferably 2 to 10ethoxy units. In another preferred embodiment, an ethoxylatedtriglyceride comprises the reaction product of a triglyceride havingfree hydroxyl groups such as castor oil; and 2 to 30 ethoxy and/orpropoxy units, preferably 2 to 10 ethoxy units. In a preferredembodiment, the HLB of the alkoxylated triglycerides is between 12 and16.

Other preferred oil-wetting surface active materials are alkylene oxideadducts of a C₆-C₃₀, preferably a C₈-C₂₄, more preferably a C₁₀-C₂₄,alcohol or phenol, including alkyl, alkaryl and aryl substitutedphenols. The alkylene oxide typically contains from two to five carbonatoms. Such surface active members include, lauryl polyoxyethyleneglycol ether, stearyl polyoxyethylene glycol ether, cetylpolyoxyethylene glycol ether, and nonylphenol polyoxyethylene glycolether. In addition, the surface active material may include ethyleneoxide adducts of linear or branched monocarboxylic acids and having HLBsof greater than about 13.5, preferably greater than about 14.

Other oil-wetting surface active materials include ethoxylated mono orpolyhydric alcohols or their derivatives. Preferred are thoseethoxylated mono or polyhydric alcohols prepared from C₉-C₁₁ alkylalcohols ethoxylated with from about 7 to about 10 moles of ethyleneoxide per mole of alcohol. Such surface active materials includetridecanol ethoxylate.

In a more preferred embodiment, the polyoxyalkylene glycol etherscontain hydrophobic and hydrophilic blocks, each block preferably beingbased on at least one oxyethylene group or oxypropylene group or amixture thereof. Exemplary of such surface active materials are thoseset forth in U.S. Pat. No. 6,395,686, herein incorporated by reference.

Also preferred are reactive surface active materials of the formulaR₁O—(CH₂CHR₂O)_(x)—(CH₂CH₂O)_(y)—(CH₂CHR₃O)_(z)—R₄ where R₁ is eitheralkyl, aryl, alkylaryl, or aralkylaryl of 8-30 carbon atoms, R₂ is—CH₂OCH₂CH═CH₂ (AGE); R₃ is either H, CH₃ or CH₂CH₃; R₄ is H or —SO₃M or—PO₃M where M is H or K, Na, NH4, NR4, alkanolamine, or other cationicspecies and x=2-100; y=4-200 and z=0-50. Such reactive surface activematerials are set forth in U.S. Pat. No. 9,051,341, herein incorporatedby reference.

The non-aqueous slurry is preferably a non-aqueous oil based slurrycontaining the surface active material, borate salt as crosslinkingagent and organophilic clay. The oil based slurry may be produced byfirst adding the organophilic clay to the hydrocarbon derived oil torender a clay enriched oil slurry. When necessary, the clay activatormay be added to the clay enriched oil slurry. Typically, theorganophilic clay and hydrocarbon derived oil and, when needed, clayactivator are mixed in a blender at room temperature until the oilmixture thickens to a viscosity in excess of 12 cP at 511 sec⁻¹, andpreferentially above 15 cP. The oil-wetting surface active material maythen be added to the clay enriched oil slurry followed by the additionof the boron crosslinker. The oil-wetting surface active material andboron crosslinker may be added directly into the blender containing theclay enriched oil slurry and oil-wetting surface active material.Typically, the mixing described herein is at room temperature with thetemperature range dictated by seasonal temperatures.

The non-aqueous slurry may further include a pH adjustment agent (suchas sodium hydroxide, potassium hydroxide, sodium bicarbonate, potassiumbicarbonate and an amine) and/or a pH buffering agent (such as potassiumcarbonate) in order to adjust the pH of the aqueous well treatment fluidto about 9.5 to 11.5 prior to crosslinking.

The non-aqueous slurry may be added to an aqueous fluid containing thegellant. The resulting fluid may then be pumped into the well as afracturing fluid. Typically, the amount of gellant in the aqueousfracturing fluid is between from about 0.21 to about 1.05, morepreferably from about 0.29 to about 0.84, most preferably from about0.33 to about 0.50, ppb of the aqueous fracturing fluid.

The gellant, instead of being added to the aqueous fluid as a drypowder, may be first dispersed in a non-aqueous containing slurry(“non-aqueous gellant containing slurry”). The non-aqueous gellantcontaining slurry may then be added, with the non-aqueous slurrycontaining the crosslinking agent, to an aqueous fluid and the resultingaqueous fluid is then pumped into the well as an aqueous fracturingfluid. Typically, the amount of gellant in the non-aqueous gellantcontaining slurry is between from about to about 185, preferably fromabout 160 to about 170, ppb of the non-aqueous gellant containingslurry. The weight ratio of non-aqueous oil slurry containingcrosslinking agent to non-aqueous gellant containing slurry in theaqueous well treatment fluid is generally between about 1:25 to about2:1, preferably from about 1:25 to about 1:1, more preferably from about2.0:49.5 to about 15.8:17.2, for example about 1:7 to about 1:2.

The non-aqueous gellant containing slurry contains a non-aqueous liquidand the gellant. Preferably, the non-aqueous liquid is an oil, such asany of the oils referenced above used in the oil-based slurry containingthe crosslinking agent. The non-aqueous gellant containing slurryfurther preferably contains an organophilic clay. The organophilic claymay be any of the organophilic clays present in the oil based boratecontaining slurry. While the organophilic clays in the oil based boratecontaining slurry and the oil based gellant containing slurry aretypically the same, different organophilic clays may be used as well.Typically, the amount of organophilic clay in the non-aqueous gellantcontaining slurry is between from about 3.6 to about 7.5, preferablyfrom about 4.5 to about 5.5, ppb of the non-aqueous gellant containingslurry.

The non-aqueous based gellant containing slurry may be prepared by theaddition of the organophilic clay to the oil. The oil may be any of theoils used in the oil-based slurry containing the crosslinking agent.When necessary, an activator may be added to the clay enriched oil. Theclay may need to be activated in the oil. Suitable clay activatorsinclude propylene carbonate, ethanol and combinations thereof. Whenpresent, the amount of clay activator typically ranges from about 15% toabout 40%, typically around 25%, to the weight of the clay.

Further, a water wetting surface active material may be added to thenon-aqueous gellant containing slurry. The water wetting surface activematerial is typically added to the oil prior to the addition of thegellant. Once the non-aqueous gellant containing slurry is added to theaqueous fluid, the water-wetting surface active material aids in theremoval of the oil from the surface of the gellant and thus facilitateshydration of the gellant.

The water-wetting surface active material may be nonionic, anionic,cationic or amphoteric. Examples of suitable water wetting surfaceactive materials include ethoxylated nonylphenol surface activematerial, polyoxyethylene sorbitan based surface active materials, fattyalcohol ethoxylates, such as tridecyl alcohol ethoxylate, etc. Whenpresent, the amount of water-wetting surface active material in thenon-aqueous gellant containing slurry is between about 0.1% to about10%, preferably from about 0.15% to about 3%, more preferably from about0.2% to about 0.3% by weight based on the total weight of thenon-aqueous gellant containing slurry.

The non-aqueous slurry containing the crosslinking agent and thenon-aqueous gellant containing slurry may be prepared and transported tothe wellsite. The non-aqueous gellant containing slurry and the slurrycontaining the crosslinking agent may be mixed sequentially in theaqueous treatment fluid at the wellsite depending on the needs of theoperator. Typically, the weight ratio of slurry containing thecrosslinking agent to non-aqueous gellant containing slurry in theaqueous well treatment fluid is between from about 1:25 to about 2:1,preferably from about 1:25 to about 1:1, more preferably from about2.0:49.5 to about 15.8:17.2, for example about 1:7 to about 1:2.Preferably, at the wellsite, the non-aqueous slurry containing thecrosslinking agent may be added to an aqueous fluid containing thegellant. In such instances, dry powder as gellant may be added to theaqueous fluid at the wellsite before or after the addition of thenon-aqueous slurry containing the crosslinking agent.

Any of the organophilic clay, oil and clay activator in the non-aqueousgellant containing slurry may be the same or different as those in thenon-aqueous slurry containing the crosslinking agent. In a preferredembodiment, the organophilic clay, non-aqueous liquid and clay activatorin the non-aqueous slurry containing the crosslinking agent are the sameas those in the non-aqueous oil gellant containing slurry.

The gellant is crosslinkable with the crosslinking agent.

Exemplary gellants are hydratable polymers and include polysaccharidessuch as cellulose, starch, and galactomannan gums. Suitable celluloseand cellulose derivatives include alkylcellulose, hydroxyalkyl celluloseor alkylhydroxyalkyl cellulose, carboxyalkyl cellulose derivatives suchas methyl cellulose, hydroxyethyl cellulose, hydroxypropyl cellulose,hydroxybutyl cellulose, hydroxyethylmethyl cellulose,hydroxypropylmethyl cellulose, hydroxylbutylmethyl cellulose,methylhydroxyethyl cellulose, methylhydroxypropyl cellulose,ethylhydroxyethyl cellulose, carboxyethylcellulose,carboxymethylcellulose and carboxymethylhydroxyethyl cellulose. Specificgalactomannan gums and derivatized galactomannan gums includeunderivatized guar, hydroxypropyl guar, carboxymethyl guar, hydroxyethylguar, hydroxypropyl guar, carboxymethylhydroxyethyl guar andcarboxymethylhydroxypropyl guar. Preferred are un-derivatized guar,carboxymethyl guar, carboxymethyhydroxypropyl guar and hydroxypropylguar.

Other suitable polysaccharides include locust bean gum, tara gum orfenugreek gum or a mixture thereof.

Crosslinking of the gellant may be accomplished in two steps. First, thepH of the treatment fluid may be increased for hydration from a pH rangeof about 6.6 to 8.5 to a pH range between from about 9.5 to about 11.5for crosslinking. The increase in pH may be by the use of common basessuch as sodium hydroxide, potassium hydroxide, ammonium hydroxide,amines such as monoethanol amine, potassium carbonate or mixtures ofthese. Second, the crosslinking agent is one which completely dissolveswithin 30 sec to 3 min when added to the non-aqueous gellant containingslurry. For operational simplicity, metering and mixing is bestaccomplished by pumping a slurried dispersion of the borate salt in oil.

The preferred slurries are those composed of the borate salt dispersedin a non-solvent for the borate. The concentration of the borate powderin the oil depends on the amount of boron released from the salt whendissolved in the fracturing fluid. Typically, the borate ionconcentration should range from about 200 to 1000, preferably from about250 to 800, ppm per gallon of the slurry when added to 1000 gallon offracturing fluid. More preferred is 350 to 600 ppm borate ion per gallonslurry per 1000 gal of fracturing fluid. These powders are normallysized as 70/140 mesh.

At the wellsite, well treatment additives may be added as needed to thefluid. Such additives may include one or more scale inhibitors,corrosion inhibitors, biocides, breakers, biocides, stabilizers, gashydrate inhibitors, mutual solvents, bactericides, paraffin inhibitors,asphaltene inhibitors, iron control agents, relative permeabilitymodifiers, sulfide scavengers and mixtures thereof.

In an embodiment, the amount of hydrocarbon based oil in the aqueouswell treatment fluid is from about 10 about 25 ppb of the aqueous welltreatment fluid, the amount of oil-wetting surface active material inthe aqueous well treatment fluid is from about 0.03 to about 0.1 ppb ofthe aqueous well treatment fluid; the amount of crosslinking agent inthe aqueous well treatment fluid is from about 1 to about 4 ppb of theaqueous well treatment fluid; the amount of organophilic clay in theaqueous well treatment fluid is from about 0.3 to about 1 pound perbarrel of the aqueous well treatment fluid; and the amount of gellant inthe aqueous well treatment fluid is from about 7 to about 16.5 ppb ofthe aqueous well treatment fluid.

The loading of gellant in the aqueous well treatment fluid may rangefrom about 6 to about 40 lb/1000 gal water, typically from about 8 toabout 15 lb/1000 gal and more typically between from about 8 to about 12lb/1000 gal of water. It is the viscoelasticity of the gellant whichenables the low loadings of gelling agent in the aqueous well treatmentfluid.

The viscosity of the aqueous well treatment fluid introduced into thewellbore is typically less than 20 cP, more typically between 10 cP and20 cP at 40 sec⁻¹. The viscosity of the aqueous well treatment fluidrapidly decreases when exposed to operational shear stresses. Forinstance, the viscosity of the aqueous well treatment fluid may be fromabout 4 to about 9 cP at 511 sec⁻¹ after introduction of the fluid intothe wellbore. Where the crosslinking agent is a borate salt and thenon-aqueous liquid is oil, the crosslinked gel viscosity, after theborate salt crosslinking agent crosslinks with the water-solublegellant, may be from about 200 to 2,000 cP at 40 sec⁻¹.

Once in the fracture, thermal thinning of the fluid reduces viscosity sothat high fluid velocity rather than viscosity places the proppant inthe fracture. (The proppant referenced herein may be any recognizedproppant in the field and may include sand, bauxite, coated sand, coatedbauxite, a synthetic resin, a coated resin and include lightweightmaterials having a specific gravity less than sand or bauxite.) Forinstance, after formation of the crosslinked gel, the viscosity of thefluid at in-situ temperature conditions above 160° F. may be from 10 to20 cP at 40 sec⁻¹. The thinned fluid, having a viscosity between 5 and20 cP at 40 sec⁻¹, but having a larger viscosity than frictionreducer-laden slickwater or linear gels, has substantially lowerviscosity than conventional crosslinked fluid viscosity. It is thusbetter able to promote fracture complexity growth needed to increaseproduction in the reservoir.

In light of the phenomena of thermal thinning of the fluid at in-situconditions, the aqueous well treatment fluid may be characterized as a“lipping gel”. As used herein, the term “lipping gel” (also referred toas “tonguing gel”) refers to a deformable gel that undergoes deformationwhen a container housing the gel is tipped through an angle of 45°-90°.Deformation of the gel may take place by forming a “lip” or a “tongue”that can be retrieved into the container by returning the container backto its upright position. For instance, the reaction of a borate saltcrosslinking agent and the gellant in a hydrocarbon based oil slurry athigh pH conditions produces the crosslinked gel, thermal thinningoccurring above about 130° F.

Unlike traditional fracturing where bi-wing fractures are formed, in thefracturing of low permeability reservoirs, such as shale, the fracturingfluid is a low viscosity fluid in the fracture. This enables thecreation of multiple fractures, i.e., the formation of a fracturenetwork, in a relatively short period of time. The majority offracturing in low permeability reservoirs is in horizontal wellbores.Whereas in conventional fracturing, the fracturing fluid remains in thebi-wing, in the fracturing of low permeability reservoirs, it isimportant that the proppant in the fluid be carried quickly verticallyinto the well and then into the horizontal part of the well and acrossthe perforations. Thus, it is desirable that the viscosity of the fluidbe lower in the vertical portion of the well to minimize high frictionpressures to minimize expensive pumping hydraulic horsepower, this beingthe importance of the delay crosslinking. Upon reaching the heel of thehorizontal portion of the well, higher crosslinked viscosity is needed,especially fluids exhibiting viscoelastic characteristics, to transportor carry larger size and amounts of the proppant along the horizontalsection of the well and across the perforations connecting the well tothe reservoir. Once the fluid enters the reservoir, the fluid shouldthermally thin to a low viscosity fluid, maintaining 10 to 40 cP,typically less than 20 cP, at 40 sec⁻¹, in order for it to generatefracture complexity.

The aqueous well treatment fluid thus exhibits a higher viscosity thanslickwater in the complex fracture network. The viscosity of the fluidis quickly decreased due to the natural reservoir temperatures. Thefluid thins back to a viscosity which is more than linear gel (at most6-7 cP at 511 sec⁻¹) itself at elevated temperatures of 130 to 140° F.which is sufficiently thin to initiate the secondary and tertiaryfractures needed for shale production enhancement.

The aqueous fracturing fluid having a low loading of gellant furtherprovides an excellent media for proppant transport. Proppant issuspended in the fracturing fluid in the near well portion of thefracture until thermal thinning reduces the proppant carrying capacity.This is the case even where the loading of gellant is from 6 to 8 poundsper 1,000 gallons (pptg) of water. The capability of proppant transportin the fluid containing low loading of gellant is attributable to theelasticity of the fluid (evidenced by the fluid being a lipping gel).

Being almost ten times higher than the viscosity of slickwater, the welltreatment fluid provides for better proppant placement than slickwateroperations. The crosslinked gel structure coupled with the low viscosityof the well treatment fluid further enables the transport of higheramounts of proppant into the formation than that offered by slickwater.Proppant placement into the secondary fractures within the createdfracture network is therefore more efficient. Thus, the aqueousfracturing fluid provides a transport media for carrying larger volumesof proppant across the lateral and perforations than in a slickwaterprocess but yet allows the fluid to revert back to near-slickwaterbehavior in the fracture.

The use of the aqueous fluid disclosed herein reduces damage to thesubterranean formation being subjected to the fracturing operationcompared to conventional fracturing fluids. The reaction between thecrosslinking agent and gellant is delayed by the presence of theoil-wetting surface active material in the slurry as the oil-wettingsurface active material decreases the rate of wetting of thecrosslinking agent by water. Since the reaction between the crosslinkingagent and gellant is delayed, less gellant is needed to carry proppantinto the formation. Typically from about 6 to 12 pptg water of gellantis in the fluid. Fluids having low loadings of gellant reduce damage tothe formation caused by the presence of gellant.

Further, due to viscosity loss by thermal thinning, the fracturingfluid, having low polymer loading, tolerates a more aggressive amount ofbreaker than conventional gels. Breakers are normally included infracturing fluids in order to reduce fluid viscosity so that degradedfracturing fluid can be recovered while leaving the proppant in thefracture network. Breakers are designed to degrade the polymer gel toprevent gel residue-related flow impairment in the proppant pack.Conventional breakers include strong oxidizing agents such as ammoniumor sodium persulfate, hydrogen peroxide, calcium peroxide, magnesiumperoxide, t-butyl hydroperoxide, cumene hydroperoxide and sodiumchlorite. In addition, breakers can include enzymes capable of degradinggalactomannan polysaccharide gelling agents. These enzymes includehemicellulases, amylases as well as guar specific enzymes, such asgammanases.

The type and amount of breaker is normally determined by lab testingprior to the fracturing treatment. The amount of breaker, referred to asthe breaker schedule, is normally based on rheology testing as describedin API's ISO 13503-1, formerly RP-39. Ideally, the amount of breaker inthe fluid has minimal effects on the viscosity of the fracturing fluidearly in the treatment to allow proppant placement in the fracture. Fortemperatures between 130° F. and 180° F., ammonium or sodium persulfatecan be used at concentrations such as 0.25 to 2.0 lb/1000 gal. Enzymescan be used in the diluted form from the concentrate by diluting theconcentrate such as Elanco's High pH Enzyme Breaker with 1 part enzymeconcentrate to 299 parts (by vol) and using 0.25 to 5.0 gpt. Attemperatures greater than 180° F., the amount of enzyme breaker in thefracturing fluid may be 0.25 to 5.0 gpt of a 10% (by wt) sodium chloritesolution. Afterward, the breaker degrades the fracturing fluid to allowmaximum fluid recovery and no gel damage that could cause flowimpairment in the proppant pack. In practice, some flow impairmentresults because of a loss of viscosity early in the treatment operation.This viscosity loss should be an insufficient amount to allow completedegradation of the fluid.

Since the fracturing fluids set forth herein may have low polymerloading, significant viscosity loss occurs due to thermal thinning ofthe fluid. The fluid can thus tolerate high amounts of breaker as thecomplexity of the fracture grows. In this case, the well temperatureadjacent the perforations, after several tubing volumes of fluid, istypically from 5° F. to about 20° F. warmer than the fluid temperatureon the surface. The lower temperature prevents the oxidizer breaker fromactivating, allowing the fluid to transport proppant from the surface,along the lateral and across the perforations without significantlyeffecting viscosity. Once in the fracture, thermal thinning reduces theviscosity of the fluid such that fluid velocity rather than viscosityplaces the proppant in the fracture. The thinned fluid, having aviscosity between 5 and 20 cP but having a larger viscosity thanfriction reducer-laden slickwater or linear gels, has substantiallylower viscosity than conventional cross-linked fluids. This lowerviscosity is better able to promote fracture complexity and thusincreases production from the reservoir. This is especially the casewith shale reservoirs.

Due to viscosity loss by thermal thinning, the ultra-low polymerfracturing fluid can tolerate more aggressive amounts of breaker thanconventional gels. Typically, the amount of breaker in the fracturingfluid is from about 0.001 to about 0.024, preferably from about 0.003 toabout 0.018, more preferably from about 0.006 to about 0.012, based onthe total weight of the fracturing fluid. This tolerance to breakerpromotes less proppant pack damage and less flow impairment through theproppant pack, allowing enhanced oil or gas production.

EXAMPLES

The following examples are illustrative of some of the embodiments ofthe present disclosure. Other embodiments within the scope of the claimsherein will be apparent to one skilled in the art from consideration ofthe description set forth herein. It is intended that the specification,together with the examples, be considered exemplary only, with the scopeand spirit of the disclosure being indicated by the claims which follow.

All percentages set forth in the Examples are given in terms of weightunits except as may otherwise be indicated.

Example 1

The slurries were prepared in the order of addition from top to bottomusing a lightning stirrer using the weights defined in Table 1. 500 mlof tap water was poured into a WARING blender. The slurry was preparedas follows: 1.0 ml of a guar slurry containing 0.48 g of guar gum wasmixed for several minutes until the gum was hydrated. The pH wasadjusted to pH 10.0 with 25% sodium hydroxide solution. The blenderspeed was then adjusted to 1300 rpm to create a vortex. The 0.7 ml ofthe crosslinking agent was added to the solution and a stopwatchstarted. The time needed for the vortex to close was measured for eachslurry formulation. This test shows that by varying the surface activematerial loadings, the time of crosslinking can be controlled. (Thevortex in the blender closes as the polymer crosslinks and increases ingel strength or viscosity.)

All surface active materials in the examples are oil-wetting agents forborax.

TABLE 1 Product Test Numbers Slurry Components Trade Name ManufacturerF1 F2 F3 4 Hydro-treated Naphtha (g) LPA-170 Sasol 87 85 83 81 Ethox3571(g) Ethox 3571 Ethox 0 1 2 3 Ethoxylated Coconut Glyceride (g) Ethox1212Ethox 0 1 2 3 Organophilic Clay (g) Claytone SF Southern Clay 3 3 3 3Propylene carbonate (g) 0.6 0.6 0.6 0.6 Sodium Tetraborate decahydrate(g) 60 60 60 60 Ethsorb-L (g) Ethsorb-L Ethox 0.2 0.2 0.26 0.4 closuretime (seconds) 17 20 26 34 Note: 8# gel system, pH = 10.0, 0.7 ml in 500ml (1.4 gpt loading), 1300 RPM

Example 2

The slurries were prepared in the order of addition from top to bottomusing a lightning stirrer and using the weights defined in Table 2.After the slurries were prepared, 250 ml of tap water was poured into aWARING blender. The water was treated 0.50 ml of a guar slurrycontaining 0.24 g of guar gum and mixed for several minutes until thegum was hydrated. The pH was adjusted as shown in the chart with 25%sodium hydroxide solution. The blender speed was then adjusted to 980rpm to create a vortex. Then, 0.35 ml of the crosslinking agent wasadded to the solution and a stopwatch started. The time needed for thevortex to close was measured for each slurry formulation. This testshows that by varying the surface active material type as compared toTable 1 and the loadings, the time of crosslinking can be easilycontrolled.

TABLE 2 Product Test Numbers Slurry Components Trade Name ManufacturerF5 F6 F7 F8 F9 F10 Hydro-treated Naphtha (g) LPA-170 Sasol 87 87 87 8787 87 Polyoxyethylene Glycol Ether (g) Ethox2988 Ethox 0 0 0 0 1.5 1.5Ethoxylated Coconut Glyceride (g) Ethox1212 Ethox 1.5 1.5 2 2 0 0Organophilic Clay (g) Claytone SF Southern Clay 3 3 3 3 3 3 Propylenecarbonate (g) 0.6 0.6 0.6 0.6 0.6 0.6 Sodium Tetraborate decahydrate (g)60 60 60 60 60 60 pH = 10.71 10.88 10.88 10.95 10.75 11.03 closure time(seconds) 43 50 70 75 53 69 Note: 8# gel system, 0.35 ml in 250 ml (1.4gpt loading), 980 RPM

Example 3

The slurries were prepared in the order of addition from top to bottomusing a lightning stirrer and using the weights defined in Table 3.After the slurries were prepared, 500 ml of tap water was poured into aWARING blender. The water was treated 1.0 ml of a guar slurry containing0.48 g of guar gum and mixed for several minutes until the gum washydrated. The pH was adjusted to pH 10.0 as shown in the chart with 25%sodium hydroxide solution. The blender speed was then adjusted to 1250rpm to create a vortex. Then, the crosslinking agent was added, based onthe volume shown in the chart, to the solution and a stopwatch started.The time needed for the vortex to close was measured for each slurryformulation. This test shows that by varying the surface active materialamount in the slurry and the loadings, the time of crosslinking can beeasily controlled and can be extended to long periods of time, ifneeded.

TABLE 3 Product Test Numbers Slurry Components Trade Name ManufacturerF11 F12 F13 F14 F15 Hydro-treated Naphtha (g) LPA-170 Sasol 40 25 25 2525 Organophilic Clay (g) Claytone SF Southern Clay 1.5 0.95 0.95 0.950.95 Propylene carbonate (g) 0.3 0.172 0.172 0.175 0.175 SodiumTetraborate decahydrate (g) 25 17.537 25 22 19 Polyhydroxy Ester-based(g) Ethox 2974 Ethox 25 13.6 11 4 2.3 pH = 10 10 10 10 10 loading (gpt)= 1 2 1.4 2 2.2 Closure time (seconds) 180 >180 >180 94 94 Note: 8# gelsystem, 1250 RPM

Example 4

The slurries were prepared in the order of addition from top to bottomusing a lightning stirrer and using the weights defined in Table 4. Inthis table, a mixture of the deca- and pentahydrate were tested toevaluate the wetting effect on different types of borate salts. Afterthe slurries were prepared, 500 ml of tap water was poured into a WARINGblender. The water was treated 1.0 ml of a guar slurry containing 0.48 gof guar gum and mixed for several minutes until the gum was hydrated.The pH was adjusted to about pH 10.0 as shown in the chart with 25%sodium hydroxide solution. The blender speed was then adjusted to 1300rpm to create a vortex. Then, the cross-linking agent was added, basedon the volume shown in the chart, to the solution and a stopwatchstarted. The time needed for the vortex to close was measured for eachslurry formulation. This test shows that by varying the surface activematerial amount in the slurry and the loadings, the time of crosslinkingcan be easily controlled and can be extended to long periods of time, ifneeded.

TABLE 4 Product Test Numbers Slurry Components Trade Name ManufacturerF16 F17 F18 F19 Hydro-treated Naphtha (g) LPA-170 Sasol 25 25 25 50Organophilic Clay (g) Claytone SF Southern Clay 0.95 0.95 0.95 1.9Propylene carbonate (g) 0.175 0.175 0.175 0.35 Sodium Tetraboratedecahydrate (g) 0 17 17 38 Sodium Tetraborate pentahydrate (g) 19.5 2.52.5 0 Polyhydroxy Ester-based (g) Ethox 2974 Ethox 3.2 3 2 4 pH = 10.07loading (gpt) = 1.6 1.8 1.6 2 Closure time (seconds) 20 94 68 110 Note:8# gel system, 1300 RPM

Example 5

The slurries were prepared in the order of addition from top to bottomusing a lightning stirrer and using the weights defined in Table 5. Inthis table, a mixture of the sodium octaborate tetrahydrate was testedto evaluate the wetting effect on different types of adsorbing surfaceactive materials. After the slurries were prepared, 500 ml of tap waterwas poured into a WARING blender. The water was treated 2.5 ml of a guarslurry containing 1.20 g of guar gum and mixed for several minutes untilthe gum was hydrated. The pH was adjusted to about pH 10.0 as shown inthe chart with 25% sodium hydroxide solution. The blender speed was thenadjusted to 1300 rpm to create a vortex. Then, the crosslinking agentwas added, based on the volume shown in Table 5, to the solution and astopwatch started. The time needed for the vortex to close was measuredfor each slurry formulation. This test shows that by varying the surfaceactive material type in the slurry, the time of crosslinking can beeasily controlled and can be extended to long periods of time, ifneeded.

TABLE 5 Product Trade Test Numbers Slurry Components Name ManufacturerF20 F21 Hydro-treated Naphtha (g) LPA-170 Sasol 66.39 66.39 OrganophilicClay (g) Claytone Southern 2.48 2.48 SF Clay Propylene carbonate (g)0.46 0.46 Disodium Octaborate Tetra Hydrate (g) 30.52 30.52 Tridecylalcohol 9 mole EO TDA-9 BASF 0.00 0.15 Polyhydroxy Ester-based (g)Ethsorb-L Ethox 0.15 0.00 pH = 10.0 10.0 loading (gpt) = 1.0 1.0 Closuretime (seconds) at 39° F. 136 130 Closure time (seconds) at 34° F. 191151 Note: 20# gel system, 1300 RPM

Example 6

Hydraulic fracturing fluids are designed to create optimum fracturegeometry, that being length and a fracture width to allow entry of theproppant. The fluid is also designed to carry the proppant from thesurface to the fracture, especially in horizontal wells that employextensive horizontal laterals that can be 3000 to 6000 feet in distance.Unlike vertical wells, in the horizontal portion, gravity forces areperpendicular to the direction of fluid flow, these forces responsiblefor sand settling and banking in the wellbore. This example shows thefluid of this invention is capable of transporting proppant in thehorizontal portion of the well.

Into 500 ml of tap water mixing in a Waring™ blender was added 1.5 ml ofa guar gum dispersed in mineral oil with an equivalent concentration of12 lbs of guar gum per 1000 gallons of fracturing fluid. The fluid wasmixed at 1500 rpm for two minutes and then adjusted to pH 10.0 with 25%(wt) sodium hydroxide solution. After pH adjustment, the fluid wastreated with 0.70 ml of the crosslinking agent defined in Example 5formulation F20 and 120 g of 20/40 Northern White Sand (specific gravity2.65) and mixed for one minute at 1300 rpm. The sand concentration isequivalent to 2 lb/gal.

After mixing, the sand-laden gel was poured into a 500 ml graduatedcylinder at 72° F. and a timer started. In comparison, the sand fall wascompared to a guar polymer solution at the same concentration butwithout crosslinking. The fall was 15 inches in 2.5 sec or 359″/min.These data are reported in Table 6. This data shows the ultra-lowpolymer based crosslinked fracturing fluid can adequately transportproppant much more efficiently than just the polymer solution withoutcrosslinking.

TABLE 6 Example 6 Example 6 Example 7 Example 7 Time Fall Distance FallRate Fall Distance Fall Rate min (inches) (in/min) Time min (inches(in/min) 10 1 0.10″/min 4 2″ 0.5″/min 15 2 0.13″/min 20 3 0.15″/min

Example 7

Into 500 ml of tap water mixing in a Waring™ blender was added 1.0 ml ofa guar gum dispersed in mineral oil with an equivalent concentration of8 lbs of guar gum per 1000 gallons of fracturing fluid. The fluid wasmixed at 1500 rpm for two minutes and then adjusted to pH 10.0 with 25%(wt) sodium hydroxide solution. After pH adjustment, the fluid wastreated with 0.80 ml of the crosslinking agent defined in Example 5formulation F20 and 120 g of 20/40 Northern White Sand (specific gravity2.65) and mixed for one minute at 1300 rpm. The sand concentration isequivalent to 2 lb/gal. After mixing, the sand-laden gel was poured intoa 500 ml graduated cylinder at 72° F. and a timer started. Incomparison, the sand fall was compared to a guar polymer solution at thesame concentration but without crosslinking. The fall was 15 inches in1.5 sec or 600″/min. These data are reported in Table 6. This data showsthe ultra-low polymer based crosslinked fracturing fluid can adequatelytransport proppant much more efficiently than just the polymer solutionwithout crosslinking.

Example 8

Into 500 ml of tap water mixing in a Waring™ blender was added 2.0 ml ofa guar gum dispersed in mineral oil with an equivalent concentration of16 lbs of guar gum per 1000 gallons of fracturing fluid. The fluid wasmixed at 1500 rpm for two minutes and then adjusted to pH 10.0 with 25%(wt) sodium hydroxide solution. After pH adjustment, the fluid wastreated with 0.80 ml of the crosslinking agent defined in Example 5formulation F20 and mixed for one minute at 1300 rpm. After mixing, 65ml of gel was syringed into a Grace 5600 sample cup and placed on therheometer at 72° F. and ambient pressure. The gel was then subjected tooscillatory shear with the frequency ranging from 0.1 to 4 Hz at 5%strain over a 5 min period. The sweeps were repeated 6 times to evaluatea change in the crosslinking density. These were examined by changes inthe storage modulus, G′ and the loss or viscous modulus, G″. This fluidis designated as Fluid A and the results are shown in the Table 7. As acomparison, the fluid of this invention was compared to a gel made withthe same polymer concentration and pH but using conventionalcrosslinkers composed of a 0.5 ml of delay crosslinker, ulexite oredispersed in a potassium formate solution and available from TBC Brinaddas FracSal Ultra and 0.4 ml of a surface borate crosslinker composed of2% boron and available from Independence Oilfield Chemicals as XLW-B2.This conventional fluid is designated as Fluid C in Table 7.

TABLE 7 Fld A Fld A Fld C Fld C 10 Fld A 25 Fld A 10 Fld C 25 Fld C Freqmin 10 min min 25 min min 10 min min 25 min (Hz) (G′) (G″) (G′) (G″)(G′) (G″) (G′) (G″) 0.1 3.5 5.6 1.5 4.9 1.0 4.5 5.5 9.1 0.2 2.9 6.2 3.04.3 1.3 4.4 0.0 4.3 0.3 12.4 8.3 6.7 7.5 5.9 5.9 6.6 6.2 0.4 11.4 7.79.7 2.3 4.5 6.9 0.0 8.6 0.5 11.0 7.3 7.8 4.6 2.6 7.2 6.7 7.2 1.0 10.56.8 10.8 5.2 3.8 6.5 8.2 3.4 2.0 15.7 2.7 18.3 9.4 7.0 4.4 9.7 3.4 3.020.3 4.1 17.1 18.4 14.0 6.0 12.2 8.2 4.0 19.0 7.6 17.3 5.9 8.2 4.8 10.20.5 5.0 20.5 0.0 16.8 5.3 7.0 5.7 6.9 4.2

This data suggests the new, novel fluid is more viscoelastic than theconventional fluid in both the short time and the long time crosslinkintervals.

While not being bound by theory, Applicants believe that the oil-wettingsurface active material in the oil slurry increases the time for thewater to displace oil from the surface of the borate particles andthereafter to dissolve the borate in the water to effect crosslinking ofthe polymer.

Although the present invention has been described with respect tospecific details, it is not intended that such details should beregarded as limitations on the scope of the invention, except to theextent that they are included in the accompanying claims.

From the foregoing, it will be observed that numerous variations andmodifications may be effected without departing from the true spirit andscope of the novel concepts of the disclosure.

1. A non-aqueous slurry comprising: (a) a non-aqueous liquid immisciblein water; (b) an oil-wetting surface active material; and (c) acrosslinking agent.
 2. The non-aqueous slurry of claim 1, wherein thenon-aqueous liquid is oil.
 3. The non-aqueous slurry of claim 2, whereinthe oil is a non-polar oil having from C₃-C₂₀ hydrocarbons.
 4. Thenon-aqueous slurry of claim 3, wherein the hydrocarbon non-polar oil ishydrotreated naphtha or raffinate.
 5. The non-aqueous slurry of claim 2,further comprising an organophilic clay.
 6. The non-aqueous slurry ofclaim 5, wherein the crosslinking agent is a borate salt.
 7. Thenon-aqueous slurry of claim 6, wherein the borate salt is selected fromthe group consisting of sodium borate decahydrate, sodium tetraboratedecahydrate, sodium tetraborate anhydrous, sodium metaborate, sodiumtetra borate pentahydrate and disodium octaborate tetrahydrate, sodiumtetraborate decahydrate, sodium borate decahydrate, sodium tetra boratepentahydrate and mixtures thereof.
 8. The non-aqueous slurry of claim 7,wherein the borate salt is sodium tetraborate decahydrate, sodium boratedecahydrate, sodium tetraborate decahydrate, sodium tetra boratepentahydrate or a mixture thereof.
 9. The non-aqueous slurry of claim 7,wherein the oil-wetting surface active material is selected from thegroup consisting of sorbitan esters, alkoxylates of sorbitan esters,polyalkoxylated glycerides, alkylene oxide adducts of a C₆-C₃₀ alcoholor a C₆-C₃₀ alkyl, arlkaryl or aryl substituted or unsubstituted phenol,polyoxyalkylene glycol ethers and mixtures thereof.
 10. The non-aqueousslurry of claim 9, wherein: (i) between from about 200 to about 235pounds per barrel of the slurry is the oil; (ii) between from about 6 toabout 10 pounds per barrel of the slurry is the organophilic clay; (iii)between from about 0.3 to about 0.75 pounds per barrel of the slurry isthe oil-wetting surface active material; and (iv) between from about 65to about 135 pounds per barrel of the slurry is the crosslinking agent.11. A well treatment fluid comprising the non-aqueous slurry of claim 9and further comprising a water-soluble gellant.
 12. The well treatmentfluid of claim 11, wherein the water-soluble gellant is underivatizedguar, derivatized guar, locust bean gum, tara gum, fenugreek gum or amixture thereof.
 13. The well treatment fluid of claim 12, wherein theoil-wetting surface active material is selected from the groupconsisting of sorbitan esters, alkoxylates of sorbitan esters,polyalkoxylated glycerides, alkylene oxide adducts of a C₆-C₃₀ alcoholor a C₆-C₃₀ alkyl, arlkaryl or aryl substituted or unsubstituted phenol,polyoxyalkylene glycol ethers and mixtures thereof.
 14. The welltreatment fluid of claim 12, wherein the water-soluble gellant ispresent in a non-aqueous gellant containing slurry and further whereinthe water-soluble gellant is dispersed in the slurry.
 15. An aqueouswell treatment fluid comprising the well treatment fluid of claim 13.16. The aqueous well treatment fluid of claim 15, wherein the viscosityof the aqueous well treatment fluid before crosslinking is from about 4to about 10 cP at 511 sec⁻¹.
 17. The aqueous well treatment fluid ofclaim 16, wherein the amount of gellant in the aqueous treatment fluidis between from about 6 to about 15 pounds per 1,000 gallons of water.18. The aqueous well treatment fluid of claim 17, wherein the amount ofgellant in the aqueous well treatment fluid is between from about 10 toabout 12 pounds per 1,000 gallons of water.
 19. A method of fracturing asubterranean formation penetrated by a well comprising pumping into thewell at a pressure sufficient to create a fracture network the aqueouswell treatment fluid of claim 15, wherein crosslinking of thecrosslinking agent and the gellant is delayed by the non-aqueous fluidduring fracturing.
 20. The method of claim 19, wherein the subterraneanformation has a permeability less than 1.0 mD.
 21. The method of claim20, wherein the viscosity of the aqueous well treatment fluid in thefractures of the fracture network is between from about 10 to about 20cP at 40 sec⁻¹.
 22. A method of enhancing the transport capability of aproppant in a hydraulic fracturing operation, the method comprisingpumping into a well penetrating a subterranean formation the aqueouswell treatment fluid of claim 15, wherein the loading of the gellant inthe aqueous treatment fluid is between from about 6 to about 15 poundsper 1,000 thousand gallons of water, the viscoelasticity of the aqueouswell treatment fluid, as measured by its storage modulus and viscousmodulus, is enhanced by the presence of the oil-wetting surface activematerial compared to a substantially similar fracturing fluid which doesnot contain the oil-wetting surface active material.
 23. The method ofclaim 22, wherein the viscosity of the aqueous well treatment fluid isbetween from about 10 to about 20 cP at 40 sec⁻¹ after thermal thinningin the fracture.
 24. A method of enhancing the recovery of oil or gasfrom an oil or gas well comprising pumping into the oil or gas wellduring a fracturing operation the aqueous well treatment fluid of claim15, wherein the aqueous well treatment fluid has a viscosity of fromabout 4 to about 20 cP, and wherein the aqueous well treatment fluidfurther comprises an enzyme breaker and wherein the amount of gellant inthe aqueous fluid is between from about 6 to about 40 pounds per 1,000gallons of water.
 25. The method of claim 24, wherein the aqueous welltreatment fluid has a viscosity of from about 6 to about 10 cP.
 26. Amethod of reducing formation damage to a subterranean formationsubjected to a hydraulic fracturing operation, the method comprisingpumping into a well penetrating the subterranean formation during thehydraulic fracturing operation the aqueous well treatment fluid of claim15, wherein the aqueous well treatment fluid has a viscosity of fromabout 4 to about 20 cP and frther wherein the amount of gellant in theaqueous fluid is between from about 6 to about 15 pounds per 1,000gallons of water.